Presently, downhole wireline tools exist that are capable of making formation pressure measurements useful in calculating formation permeability. U.S. Pat. No. 4,860,581 to Zimmerman, discloses a downhole tool of this type that can take formation fluid samples and determine formation properties. A tool of this type usually incorporates the features of a straddle packer to allow formation fluid specimens to be taken at larger flow rates than possible through a probe without lowering the pressure below the formation fluid bubble point. When used in combination with a pressure probe, the tool can obtain more meaningful permeability readings and at larger depths of investigation than previously permitted with other known tools. Additionally, these tools allow flow measurement and flow control during the creation of a pressure pulse which enhances the permeability determination. These downhole tools may be modularly constructed so that a tool can perform multiple tasks in a single descent of the tool into the borehole. Such tasks can include: a pressure profile of the zone of interest, a fluid analysis can be made at each station, multiple uncontaminated fluid samples can be withdrawn at pressures above the bubble-point, local vertical and horizontal permeability measurements can be taken at each station, a probe module can be set at a location dictated by previous measurements and the tool can perform large scale pressure build up tests.
As shown in FIG. 1, a downhole tool 1 is suspended in a borehole 13 from a wireline cable 2. A probe module 3 establishes fluid communication between the tool and the earth formation via a probe 4. This tool contains a pump module 5 for pumping contaminated fluid from the formation into the tool and a means to analyze fluid from the earth formation, both of which are described in U.S. Pat. No. 4,860,581. As shown, both contaminated fluid 6 and clean fluid 7 are located in the formation. Contaminated fluid 6 is in closer proximity to the borehole and is usually pumped out before the desirable fluid 7. From the fluid analyzer, it is determined whether the pumped fluid is undesirable contaminated fluid 6 or the desirable less/uncontaminated reservoir fluid 7. This less contaminated fluid is often referred to as the `clean` fluid. Drilling fluid (mud) 8 fills the annulus of the borehole. As known, one purpose of this mud is to control subsurface borehole pressure and stabilize the borehole to prevent formation pressure from exceeding the borehole pressure and causing a well blowout to occur. The tool 1 also contains a sample module 9 where the desired fluid sample is stored and electronic 10 and hydraulic 11 modules that supply electronic and hydraulic power respectively.
U.S. Pat. No. 4,936,139 issued to Zimmerman, describes a method for making formation pressure measurements and taking formation samples using the above-described downhole tool. In this method, a probe 4 in fluid communication with the tool body is also in contact with the borehole wall 12. To retrieve the formation fluid, a pressure drop is created in tool. This pressure drop causes formation fluid to flow from the high pressure formation to the lower pressure probe and into the tool. As previously mentioned, the formation contains various types of contaminated, undesirable and potentially hazardous fluids 6. These fluids also flow through the probe and, because these fluids are closer to the borehole and tool probe, these fluids are produced first. This initial production of contaminated fluids means that the contaminated fluid has to be pumped out of the tool before the clean formation fluid can be sampled.
In current sampling tools, the contaminated fluid is pumped into the tool and analyzed. The analysis would show that this fluid is contaminated and therefore, undesirable. Consequently, the tool pumps this fluid out of the tool and into the borehole or a dump chamber usually located at the lower end of the tool. This process continues until the tool begins to analyze clean, less contaminated reservoir fluid. At this point, the clean sample is stored in a pressurized chamber 9. However, before the tool begins to analyze the cleaner desirable fluid, a large volume of contaminated fluid will usually need to be pumped from the formation through the tool, or placed into chambers carried as part of the tool. The present system frequently cannot in practice remove sufficient quantities of fluid to ensure a clean sample. Therefore, the actual formation sample fluid still contains some contaminated fluid.
The degree of contamination that is acceptable depends upon a variety of factors:
1/ The use to which the sample analysis will be put. Some uses are not so sensitive to contamination as others, in so far as the resulting data from the sample analysis is less affected by contaminating fluids. This depends upon the type of analysis that is performed upon the samples. PA0 2/ The nature of the reservoir fluid. It has been found that the Pressure Volume Temperature behavior (PVT) of some reservoir fluids, typically oils with large volumes of gas dissolved within the oil, or gases with the potential to produce relatively large volumes of liquid when the pressure on the system is reduced, is much more sensitive to contaminating fluids than other reservoir fluids. PA0 1/ Some means of disposal of the produced fluids is necessary, often this is by burning, with associated pollution risks. PA0 2/ Burning makes it very difficult to maintain well operations confidential. The flare can be seen for many miles, and indicates to a trained observer, the nature of the fluid produced and the approximate production rate attained. PA0 3/ The operation is by its very nature, hazardous. Whilst flowing hydrocarbons to surface, on a drilling rig, it is necessary to temporarily adapt the drilling rig to become a production installation. PA0 4/ The productive capacity estimated during such a test serves only as a guide to how a well, drilled and completed as a producing well, may actually perform. PA0 5/ Samples obtained during such a test may not be representative as often it is necessary to sample fluids with a high degree of control over the pressure drawdown. This is not always possible during a DST. PA0 6/ It is costly to test, and often a well encounters more than a single productive interval. In practice many productive intervals are not tested because of the associated cost. PA0 7/ DST rarely provide complete information upon the drainage volume into which the well is placed. Such tests normally must be ran for a much longer duration (weeks or months) than a conventional DST.
Two major drawbacks are associated with this fluid sample taking process. One problem is that storing the fluid in a dump chamber limits the amount of contaminated fluid, drawn from the formation, to the size of the chamber. Additionally, the weight of the chamber full of fluid creates extra tension on the wireline which could limit the amount of tension that could be exerted on the wireline. This limitation would be critical for instance if the tool became stuck in the borehole and only a limited amount of force or tension could be exerted on the tool to loosen the tool. A second and even greater source of concern is the alternative, to a storage tank, of dumping the contaminated fluid into the borehole. In the current operation of this tool, only a few gallons of the contaminated formation fluid can be dumped into the borehole, before safety issues may arise.
By putting contaminated fluid in the borehole, there will be a mixing of the fluid with the drilling mud in the borehole. As previously stated, the weight and consistency of the drilling mud is such that the borehole pressure is maintained at a pressure at least equalizing that of the formation. If too large a quantity of formation fluid mixes with the drill mud, the borehole fluid weight and consistency could be altered such that the borehole pressure would drop below the formation pressure substantially increasing the possibility of a well blowout. Another safety issue resulting from dumping contaminated formation fluid in the borehole is that some of these fluids contain hazardous components. Since drill mud is circulated from the surface into the borehole and back to the surface, the potential for hazardous fluid components increases with more and more contaminated fluid being into the borehole. If some of these fluids reached the surface, there could be safety problems for persons at the surface. Therefore, because of problems associated with disposing of contaminated formation fluids in the conventional method of sample taking, the amount of fluid taken during a sampling procedure is limited. Furthermore, the limit on the amount of fluid that can be produced limits the amount and quality of clean formation fluid that can be sampled. If a means existed that would allow for taking a greater quantity of formation fluid without having the problem of where and how to dispose of the unwanted contaminated fluid, cleaner and better quality uncontaminated fluid samples could be taken. Cleaner samples would permit better analysis of the fluid sample and give more representative information about the formation fluids. There remains a need for a means to allow for the disposition of a sufficient amount of contaminated formation fluids during a sample taking procedure such that a sufficiently clean uncontaminated formation fluid sample is collected.
Drillstem Test (DST)
DRILLSTEM testing is another technology that is used to take a fluid sample from a formation. DRILLSTEM testing is a method used to temporarily complete a recently drilled well in a formation in order to evaluate the formation. The test can be made either in an open hole or in a cased hole with perforations. A flow string, usually a drill string of pipe, or sometimes a tubing string is used to carry the test equipment into the well. The test equipment can include packer(s), perforated pipe, pressure gauges, and a valve assembly. Packers are used to isolate the formation from drilling-mud pressure. A hook-wall or casing-packer test is used in a cased well. An openhole, single packer test with one compressional packer can be used when the formation is on or near the bottom of the well. An openhole, double-packer, or straddle-packer test with two packers is used when the formation is located off the bottom of the well. A cone-packer test is used over a conehole and a wall-cone packer test is used over a cone hole with a soft shoulder.
During the test, formation fluids are allowed to flow into the drillstem, and a sampling chamber is used to collect less contaminated formation fluids. A pressure gauge and recorder is used in the drill string to record well pressures. The time of the test is limited by the data storage capacity of the downhole recorder. The test is run for periods ranging from hours to days. The important measurements in these tests are: a) initial hydrostatic pressure, b) initial flow pressure, c) initial shut-in pressure, d) final shut-in pressure, e) final flow pressure and f) final hydrostatic pressure. The shut-in pressures are recorded on a pressure build-up curve.
The drillstem test is frequently run in four steps. There is a short initial flow (IF) period in which the tool is opened. The tool is then shut in for the initial shut-in (ISI) that may last twice as long as the flow period while the bottom hole pressure is recorded along with surface shut-in and flowing pressure. The tool is then opened again for the main flow (MF) while the flow rates, pressures and volumes are measured. The flow rates are controlled by an adjustable choke. The sample of the formation fluids is collected during such a flow period. During the final shut-in (FSI), the tool is closed. If liquid did flow to the surface, it is sent to a separator where the gas, oil and water are separated. The gas is metered and the liquid flows gauged. The fluid flow rate through the choke is reported. If the fluid does not flow to the surface, the driller measures the height of liquid in the drillstem by counting the stands of pipe in the derrick, or by other means. The test determines the type of fluids in the formation and the formation productive capacity. Pressure records made during the drillstem test are used to calculate formation pressure, permeability and the amount of formation damage. Such a system has been used for many years by the industry. It is however costly to use and has certain drawbacks:
The DST therefore is not always the best solution to meet the differing requirements for data to evaluate a well, or reservoir.
Tough Logging Conditions (TLCS)
In the past, wireline logging tools have been extended into a borehole on drill pipe. This system is known as Tough Logging Conditions System (TLCS). TLCS is a logging tool conveyance method. This method is designed to transport well logging tools into wellbores which cannot be entered using a conventional wireline cable gravity descent. A TLCS can be used to convey a well logging tool or mechanical service normally conveyed on a wireline into a wellbore for the purpose of acquiring geological, petrophysical data and/or to perform other services. The TLCS method uses drill pipe that is attached to a logging tool to push the logging tool into the wellbore. The wireline containing the means for communication between the tool and surface equipment is contained in the drill pipe. A logging run begins by adding drill pipe to a drill stand that is attached to a downhole tool to log down and subtracting drill pipe from the drill string to log up the borehole.
TLCS is necessary for logging in wellbores which generally have a well geometry that includes deviations up to and over 90 degrees from the vertical. However, the TLCS is also used to log wells which are vertical, but have obstructions in the wellbore preventing a normal gravity descent for logging tools conveyed on a wireline. Furthermore, TLCS have logging applications in depleted wells where a high differential pressure exists between the wellbore and the geological formation. This conditions may cause the wireline and/or the logging tools to become stuck against the formation resulting in a fishing job.